It is well known that fossil and nuclear power production equipment require metallurgical heat exchange components, specifically boilers, operating in harsh environments at very high temperatures and pressures, to run safely and reliably for extended periods of time, sometimes many years without scheduled equipment overhauls. By way of example, one of the most difficult of these is the large coal-fired fossil boiler.
While such examples are herein addressed, it is well known to those of ordinary skill in the art that fossil boilers, although major, make up only part of a typical reheat regenerative Rankin cycle. Further, tube failures constitute one of the industry's principle reasons for high equipment downtime and costs.
Systems and methods for managing equipment operations and addressing equipment failures are well known. By way of example, US utility patent application publication, US 2007/0169721 for Weisenstein et al. discloses online boiler tube degradation monitoring with optimization software. One disclosed method includes monitoring a degradation of steam generator boiler tubes in large combustion facilities, wherein the boiler tubes are arranged in a flue gas tract and exposed to flue gases from a combustion process. The method comprises receiving and evaluating signals indicative of a degradation of the boiler tubes from within the flue gas tract while steam is being generated. Additional features include receiving signals by degradation sensors located external to the flue gas tract, receiving ultrasonic signals by ultrasonic transducers, and receiving the signals from a test tube arranged in the flue gas tract and being exposed to the flue gases.
By way of further example, U.S. Pat. No. 7,113,890 to Frerichs et al. discloses predictive tube failure in a boiler. One disclosed method detects a fault in a component of a continuous process in a steam generator system. The method includes developing a model of the continuous process, generating predicted values for a predetermined number of operating parameters of the continuous process using the model, comparing the value predicted by the model for each of the predetermined number of operating parameters to a corresponding actual measured value for the operating parameter, and determining whether differences between the predicted and actual measured values for one or more of the predetermined number of operating parameters exceeds a configured statistical limit using Statistical Process Control (SPC) methods. The predetermined number of operating parameters of a continuous process depends on the process and is on a water/steam side of a boiler/turbine power cycle. Predetermined parameters may include make-up flow, feed water flow and condensate flow.
Yet further, U.S. Pat. No. 6,567,795 to Alouani et al. also discloses predictive tube failure in a boiler. Nevertheless, mechanical equipment failures remain a major cause of forced outages for fossil-fueled steam generators.
By way of example of a need in the industry, consider a boiler pressure part system owner tasked with coming up with a program to eliminate boiler tube failures. The first thing the owner must do is to collect and compile data for use in building the test & inspection plan. Because it is less labor intensive and because the operators responsible for the boiler are new, it is decided that the plan must make extensive use of computerized technology. There are challenges that stand in the way of developing a good plan that must be overcome.
By way of example, challenges may include Challenge #1: The inability to analyze the influences that off-design fuel, water chemistry and negative useful life influences (hours of operation, stress/fatigue cycles, thermal cycles, etc.) the equipment is exposed to as part of day to day operation that can be manifested as damage.
Challenge #2: The boiler is large, its operating environment is extremely harsh and the problems complicated. The boiler is built with several hundred miles of heat transfer tubing and piping. Scientists have identified over thirty damage mechanisms that threaten the boilers ability to contain and circulate water to produce steam at thousands of pounds of pressure and at high temperatures. As will be seen, the present invention provides enhances a thorough understanding of the behavior of these mechanisms by dividing the boiler into smaller, more manageable pieces so that care strategies and plans, unique to each part can be designed, implemented and executed with support from available computerized information management systems.
Challenge #3: It would make sense to harness the analogue and digital data streams used by the units' computerized digital control system (DCS) and other in-service component condition monitoring software for several reasons. However obstacles must be overcome that may include when the generating unit is running well, there are long periods of time between shut-downs. This means that acquiring data necessary for trending component deterioration while the unit is down, are few and far between. There is very little time to get the data aforementioned. It is normal for units capable of producing electricity inexpensively to be returned to service as soon as possible; and power producers have reduced their operations and maintenance budgets and workforce significantly due to pressures from Wall Street and because they were lead to believe that a computer can do the tasks automatically that were once done manually. This has not panned out. In the past several years, much of the workforce expertise, that was able to deductively interpret the meaning of unit condition indications then take intelligent and timely action, has retired. Young, very capable people have replaced them but the experience is sorely missed when faced with unusual conditions. There is more data coming from the DCS's data acquisition systems than people typically have time to analyze. This diminishes the value of the investment in the data acquisition system. In addition, there is a Challenge #4 that many boilers lack the appropriate instrumentation that would enable maximized monitoring and diagnostics. Installing instrumentation is capital intensive and sometimes difficult to justify. In hindsight, if points required for condition and diagnostics had been understood, many power producers that have recently upgraded the control systems to DCS, could have absorbed most of the cost of new sensors, within the DCS upgrade project budget.
The present invention addresses such challenges.